Processing of high-pressure hydrocarbon mixtures is often problematic, and especially where such mixtures contain relatively large quantities of C5 and heavier components, and particularly C6+ BTEX hydrocarbons (i.e., benzene, toluene, and xylenes) and organic sulfur contaminants (e.g., ethyl-, propyl- and butylmercaptans and heavy thiosulfides). For example, associated gas production often contains residual amount of the C6+ heavy hydrocarbons and sulfur contaminants which often create downstream operating problems, and especially foaming and corrosion. Still further, C6+ heavy hydrocarbons and sulfur contaminants also tend to cause off-specification products in the acid gas removal units.
Therefore, numerous processing configurations and methods have been developed to treat high-pressure hydrocarbon mixtures. However, all or almost all of them fail to produce a C6+ condensate and a product gas void of the C6+ and sulfur contaminants to meet current stringent sulfur specifications. For example, U.S. Pat. No. 4,702,819 to Sharma et al. teaches use of dual fractionation zones wherein the first fractionation zone employs a side reboiler and a vapor side-stream. Such configurations allow for at least somewhat desirable levels of gas/liquid separation, however, the separation of the C5 components from the C6+ and sulfur contaminants at high pressure is often very difficult if not impossible as the relative volatility between the C5 to C6 hydrocarbons dramatically decreases at high pressures.
In another known configuration, as exemplified in U.S. Pat. No. 4,462,813 to May et al., a multi-stage compressor is connected to a wellhead, refrigeration unit, and separators. Similar to Sharma's configuration, May's configuration is relatively inefficient and energy demanding, and not suitable for high recovery of the C6+ hydrocarbons from the feed gas, particularly when processing high-pressure hydrocarbon mixtures comprising significant quantities of C6+ and sulfur contaminants.
In still further known examples, as described in RE 33,408 or U.S. Pat. No. 4,507,133 to Khan et al., the vapor stream from a deethanizer is cooled to liquefaction and contacted with a vapor phase from the hydrocarbon feed stream to separate methane, ethane, and propane vapors from the feed. Similarly, as described in U.S. Pat. No. 6,658,893 to Mealey, the feed gas is cooled to liquefy the heavier components and at least some of the C2 and lighter components. Subsequent condensation and absorption steps then allow high recovery of LPG components (i.e., C3 and C4+). Such processes are often limited to high yields of C3 and C4+ components, and are not suitable for C6+ condensates recovery.
Thus, while numerous configurations and methods for gas condensate hydrocarbon separation are known in the art, all or almost all of them suffer from one or more disadvantages. Therefore, there is still a need for improved configurations and methods for gas condensate separation, and especially for gas condensate separation from high-pressure hydrocarbon mixtures comprising significant quantities of the C6+ and sulfur contaminants.